It has been our experience that a large number of developers, building owners and architects are unaware of the requirements that are imposed by the International Building Code (IBC) that has been adopted by all 50 states. CEC has had to inform many of our clients about the requirements for Special Inspections. Chapter 17 stipulates that Special Inspections (inspections by a qualified third party) are not discretionary and are required in order to obtain a certificate of occupancy for additions and new commercial construction. There is a separate IBC Code for one- and two-family dwellings. Failure to obtain Special Inspections could put obtaining an occupancy permit at risk. The IBC states that it is unlawful to occupy any building in violation of any provision of the code.
The IBC specifies that procurement of these Special Inspections is the responsibility of the owner or the design professional in responsible charge of the project acting as the owner’s representative. The Special Inspections are not to be provided by the contractor performing the construction because it puts an inspector hired by the contractor in a conflict of interest. Special Inspections may include inspections/testing of soils and earthwork, foundations, reinforced concrete, reinforced masonry, structural steel, welds, high strength bolts, etc. Special Inspections are more detailed and comprehensive than traditional construction monitoring/testing and are required to be performed by trained and certified inspectors. The International Code Council (author of the IBC) tests and certifies Special Inspectors. Special Inspectors are certified for specific types of construction activities only after completing courses of study and testing.
Owners and cost estimators should note that properly conducted Special Inspections for a project cost more than traditional inspections. This is because the Special Inspector must be onsite longer to complete the code-required inspections and testing. Based on experience with Special Inspection costs in the Carolinas where Special Inspections have been required for over 10 years, costs can vary from between 1 to 2 percent of the construction cost, depending on the size of the project, the complexity of the structure, and the required Special Inspections. Although more costly to perform, a well-executed Special Inspections program can provide increased value by reducing the risk for potential litigation due to poor structure performance or failures, increasing the quality of construction, and improving records of the construction processes. These benefits can easily offset the cost increase over traditional inspections.
If you have any questions about the IBC Special Inspections, how they may impact an upcoming project, and how you can meet the IBC requirements, contact Jeffrey Woodcock, P.E. (firstname.lastname@example.org) or Micah Sayles (email@example.com) at 800-365-2324.
Clean Air Act Information Collection Request for Coal and Oil-Fired Electric Utility Steam Generating Units
The U.S. Environmental Protection Agency (EPA) has initiated work to develop emissions standards for power plants under Clean Air Act (CAA) Section 112. Pursuant to EPA’s authority under Section 114 of the CAA, EPA’s Office of Management and Budget (OMB) approved and issued an Information Collection Request (ICR) on December 24, 2009 requiring all US power plants with coal-or oil-fired electric generating units to submit emissions information for use in developing the proposed emissions rule for air toxics. The ICR requests owners/operators of all coal- and oil-fired electric utility steam generating units provide information that will allow EPA to assess the emissions of hazardous air pollutants (HAP) from each such unit. This information will be used by the Administrator of EPA in developing National Emission Standards for Hazardous Air Pollutants (NESHAP) under CAA Section 112.
The facilities that received the ICR were selected based on the definition of an electric steam generating unit under the CAA Section 112(a)(8) which “defines an electric utility steam generating unit as any fossil fuel-fired combustion unit of more than 25 megawatts that serves a generator that produces electricity for sale. A unit that cogenerates steam and electricity and supplies more than one-third of its potential electric output capacity and more than 25 MWe output to any utility power distribution system for sale is also considered a utility unit.”
The ICR is composed of two major components. The first component is a survey issued to all coal- and oil-fired electric utility steam generating facilities listed in the 2007 version of the Department of Energy’s (DOE) Energy Information Administration’s (EIA) Forms 860 and 923, “Annual Electric Generator Report,” and “Power Plant Operations Report,” respectively. The survey requires the facility to self report specific information such as:
- identification and confirmation of existing generating unit,
- the unit design, operations,
- fuel analysis; and,
- emissions data.
This ICR survey solicits data for the most recent 12 months of fuel analysis and emissions test data for all tests conducted since January 01, 2004. The first component of the ICR is due to EPA within 90 days of receipt of the ICR.
EPA selected a limited number of facilities to complete the second component of the ICR. The second component was designed to collect sufficient information for EPA to evaluate whether specific HAPs can be addressed in future regulations through the use of surrogates and to validate the performance of specific type facilities. This component will require a limited number of facilities to conduct emissions testing for specific HAPs in accordance with EPA approved sampling and analytical protocols. Coal-fired and oil-fired units that are required to conduct stack testing must conduct emissions testing for one to four different categories of HAPs. These categories of HAPs are mercury and non-mercury metallic HAP (e.g., As, Pb, Se), acid gas HAP (e.g., HCl, HF, HCN), non-dioxin/furan organic HAP (e.g. volatiles, semi-volatiles, carbon monoxide, formaldehyde) and dioxin/furan organic HAP (e.g. dioxin/furans and PCB’s). The testing requires the performance of three emission test runs at the appropriate sampling location utilizing approved sampling protocols with specified sampling volumes and specific analytical techniques for each parameter. In conjunction with the emissions testing, each facility responding to the second component of the ICR is required to collect and analyze three fuel samples from the fuel fed to the boiler during each stack test.
The results of the emissions tests and the fuel analyses are required to be submitted to the EPA electronically along with PDF copies of all supporting documentation through EPA’s Electronic Reporting Tool (ERT) system. The selected facilities are required to conduct emissions testing and submit the emission results and fuel analysis data within eight months of receipt of the ICR. The EPA has established an ICR website, http://utilitymacticr.rti.org, where responses to questions, updates to specific information and copies of the ICR can be found.
It should be noted, that units have been identified to the best of the Agency’s ability for the purpose of this ICR action only. The receipt of the ICR for information or testing does not constitute a final Agency applicability determination for a facility related to the rule under development. Similarly, units not receiving an ICR may ultimately be determined to be subject to the final rule. Specific applicability definitions will be developed during the rulemaking process and will be subject to notice and comment. EPA has negotiated a draft Consent Decree that calls for the proposed rule no later than March 16, 2011 and a final rule no later than November 16, 2011.
If your facility has been affected by the ICR, or if you have any questions regarding the sampling, analysis or reporting under the second major component of the ICR, please contact Frank Stevens at 866-250-3679 or through email at firstname.lastname@example.org
As discussed in an earlier posting, Greenhouse Gas (GHG) reporting will be required for 24 source categories (in some cases dependent on emission levels) and facilities with stationary fuel combustion sources that meet specific criteria. Subpart C deals with the specific reporting, recordkeeping and verification requirements for GHG emissions from fuel combustion.
Starting in 2010, GHG emissions reporting will be required of facilities that have stationary fuel combustion sources where:
- The aggregate maximum rated heat input capacity of all units at facility exceeds 30 MMBtu/hr, and
- The facility has GHG emissions exceeding 25,000 metric tons (mt)/year
The regulations define a fuel combustion source as any device that combusts any of 55 solid, liquid or gaseous fuels and includes boilers, stationary internal combustion engines, process heaters, combustion turbines, incinerators, and various other types of equipment. The requirement addresses industrial, commercial and institutional (but not residential) uses of fuel in any combustion device with exemptions for the following:
- Portable equipment;
- Emergency generators/equipment;
- Irrigation pumps at agricultural operations;
- Flares, unless otherwise required by another subpart;
- Electricity generating units subject to Subpart D; and
- Hazardous waste combustion (unless a continuous emission monitoring system (CEMS) is used to monitor CO2 or the unit co-fires fossil fuels)
The fuel consumed as well as the annual operating hours will dictate whether reporting is required. The regulation provides equations for the calculation of GHG emissions based on the type of fuel, the default high heating value (HHV) of the fuel, and fuel-specific emission factors (EF). There are 4 “Tiers” of calculations based on the type of information available as summarized below:
- Tier 1 – use annual fuel consumption (from company records), fuel-specific HHV, and default CO2 emission factors;
- Tier 2 – use annual fuel consumption (from company records), measured fuel-specific HHV, and default CO2 emission factors;
- Tier 3 – use annual fuel consumption from company records (for solid fuels) or directly measured fuel consumption values (for liquid and gaseous fuels) and periodic fuel carbon content measurements; and
- Tier 4 – use CEMS data. There are a variety of restrictions on the use of the Tier 4 methodology. The rule should be consulted prior to using this method.
As an example, GHG emissions reporting will not be triggered unless fuel consumption exceeds the following:
|When Do You Need to Report?|
|Fuel||Design Capacity(MMBtu/hr)||Maximum Annual Fuel Use1|
|Coal||30||> 10,800 short tons|
|Fuel Oil||35||>2.3 million gallons|
|Natural Gas||50||>460 million ft3 (460,000 Therm)|
|Biogas (recovered methane)||50||>570 million ft3|
|Wood||30||> 10,600 short tons|
|Ethanol||40||> 4.3 million gallons|
1Approximate values assuming full utilization; 8,760 hours/year; and Tier 1 calculation
Regardless of the design capacity, emissions will remain below 25,000 mt/yr if the fuel consumption is below the maximum levels specified above. Similar calculations can be made for other fuel types based on the HHV and EF provided in Table C-1 of Subpart C.
Facilities with combustion units that are exempt from state air quality permitting requirements (e.g., in many states, those individually rated at less than 10 MMBtu/hr are exempt from permitting) will be subject to all of the GHG reporting and documentation requirements. For some facilities that had been tracking and reporting their GHG emissions on a voluntary basis (or due to state requirements), the new regulation may result in an increase in calculated GHG emissions due to the inclusion of GHG emissions from smaller (exempt) combustion units and/or changes in calculation methodology.
CEC recommends that facilities inventory all fuel combustion sources to evaluate whether this Subpart applies or if the facility is exempt from reporting. If you are unclear about how this rule affects your facility, please contact one of CEC’s GHG experts: Kris Macoskey, 800-365-2324, email@example.com. You may also email CEC’s GHG team for additional information at GHGENVHelp@cecinc.com.
Although the requirements for the preparation and submittal of Tier II Reports were established more than 20 years ago, we still find that some facilities are not submitting the reports or forget to submit the reports in accordance with the deadline. This can also be an issue for facilities where environmental departments have been downsized or eliminated due to current economic conditions. The Emergency Planning and Community Right-to-Know Act (EPCRA) established the requirements for Federal, state and local governments, Indian Tribes, and industry regarding reporting on hazardous and toxic chemicals. EPCRA was passed in response to concerns regarding environmental and safety hazards posed by the storage and handling of toxic chemicals. These concerns were triggered by the disaster in Bhopal, India caused by the accidental release of methyl isocyanate.
Facilities covered by EPCRA requirements must submit an Emergency and Hazardous Chemical Inventory Form to the Local Emergency Planning Committee (LEPC), the State Emergency Response Commission (SERC), and the local fire department annually. Facilities provide either a Tier I or Tier II Form although most States require the Tier II Form. Some states and counties have requirements in addition to the federal Tier II requirements.
The EPCRA Tier II Form submittal is due on March 1, 2010. The Tier II Form is required for chemicals that are stored at your facility above specific weight thresholds that are not exempted under the EPCRA regulations. The weight threshold varies for extremely hazardous substances (EHS) and is set at 10,000 pounds for other chemicals stored at your facility.
Tier II Forms must report the required information for each hazardous chemical present at your facility in quantities equal to or greater than established threshold amounts (discussed below), unless the chemicals are excluded. Hazardous chemicals are any substance for which your facility must maintain a Material Safety Data Sheet (MSDS) under OSHA’s Hazard Communication Standard (described at 29 CFR 1910.1200).
Section 311(e) of EPCRA excludes a number of substances. The OSHA regulations at Section 1910.1200(b) also stipulates various exemptions from the requirement for maintaining an MSDS for certain chemicals or materials. Minimum thresholds have been established for Tier II reporting under EPCRA Section 312. These thresholds are as follows:
- For Extremely Hazardous Substances (EHSs) – the reporting threshold is 500 pounds or the Threshold Planning Quantity (TPQ), whichever is lower. The current list of EHS chemicals and their TPQs is maintained at 40 CFR Part 355.
- For gasoline (all grades combined) at a retail gas station, the threshold level is 75,000 gallons, if the tank(s) was stored entirely underground and was in compliance at all times during the preceding calendar year with all applicable Underground Storage Tank (UST) requirements.
- For diesel fuel (all grades combined) at a retail gas station, the threshold level is 100,000 gallons, if the tank(s) was stored entirely underground and the tank(s) was in compliance at all times during the preceding calendar year with all applicable UST requirements.
- For all other hazardous chemicals for which facilities are required to have or prepare an MSDS, the minimum reporting threshold is 10,000 pounds.
Your facility needs to report hazardous chemicals that were present at your facility at any time during the previous calendar year at levels that equal or exceed these thresholds. The report covers the 2009 calendar year, beginning January 1 and ending December 31. For each chemical that your facility has listed, identify all the physical and health hazard boxes that apply. These hazard categories are defined in 40 CFR 370.2. The two health hazard categories and three physical hazard categories are a consolidation of the hazard categories defined in the OSHA Hazard Communication Standard, 29 CFR 1910.1200. <more info>
For each chemical that is reported, the Tier II form asks for specific information such as the maximum amount stored onsite, average daily amount stored onsite, number of days present onsite, and storage codes and storage location information (for non-confidential chemicals). You may elect to withhold location information on a specific chemical from disclosure to the public. The Tier II instructions provide details for submittal of confidential information. The owner or operator or the officially designated representative of the owner or operator must certify that all information included in the Tier II submission is true, accurate, and complete. An original signature is required on the submission.
To obtain Tier II reporting procedures and requirements for your state, please click on the state where your facility is located using the following EPA website link: http://www.epa.gov/oem/content/epcra/tier2.htm#state. We noted that at least one of the EPA’s website links were broken (e.g. Pennsylvania) at the time this blog page was written. Pennsylvania’s website for Tier II information is found at: http://www.portal.state.pa.us/portal/server.pt?open=514&objID=553047&mode=2.
The completed Tier II form(s) must be submitted to each of the following organizations: SERC, LEPC, and the fire department with jurisdiction over your facility. If you have any questions about EPCRA Tier II reporting requirements and whether your facility may be subject to these regulations, please contact Paul Tomiczek III, REM, P.E. at firstname.lastname@example.org or 800-365-2324. More information on EPCRA Tier II Reporting obligations and instructions for completing the Tier II report are provided at http://www.epa.gov/oem/docs/chem/t2-instr.pdf.
This blog was prepared as a reminder that your facility is required to complete and file the 2009 RCRA Hazardous Waste Report (also known as the “Biennial Report”) or your State’s equivalent hazardous waste report by March 1, 2010 if your facility met the definition of a RCRA Large Quantity Generator (LQG) during 2009; or if your facility treated, stored, or disposed of RCRA hazardous wastes on-site during 2009. We know of a number of facilities where the environmental departments have been downsized or eliminated due to economic conditions, so we thought this blog could be helpful. Your facility is a RCRA LQG for 2009 if your facility met any of the following criteria:
- Your facility generated, in any single calendar month, 1,000 kg (2,200 lbs.) or more of RCRA non-acute hazardous waste; or
- Your facility generated, in any single calendar month, or accumulated at any time, more than 1 kg (2.2 lbs.) of RCRA acute hazardous waste; or
- Your facility generated, in any single calendar month, or accumulated at any time, more than 100 kg (220 lbs.) of spill cleanup material contaminated with RCRA acute hazardous waste.
Report your facility’s current Hazardous Waste Generator status based on the date you submit your 2009 Hazardous Waste Report on the Site ID Form. Your facility’s current status could be different from the status during the 2009 Hazardous Waste Report year. Hazardous waste imported from a foreign country in 2009 must be counted in determining your facility’s generator status if your facility is the U.S. Importer.
Do not file the 2009 Hazardous Waste Report if, during 2009, your facility was not a RCRA LQG and your facility did not treat, store, or dispose of RCRA hazardous wastes on-site in waste management units subject to a RCRA operating permit. Do not file the 2009 Hazardous Waste Report if, during 2009, all hazardous waste generated at your facility was exported directly out of the United States to a foreign country. An Annual Report must be filed in this case as required under 40 CFR 262.56.
States may impose reporting requirements above and beyond the Federal requirements. Some States use a modified version of this report or their own instructions and forms to fulfill their reporting requirements. Please contact your State Office about State-specific requirements. See the State Contacts list at http://www.epa.gov/osw/inforesources/data/form8700/contact.pdf,
EPA has added the collection of additional data to incorporate changes from the Revisions to the Definition of Solid Waste Final Rule and the Subpart K Hazardous Waste at Academic Laboratories Final Rule. EPA has also made some editorial changes to the instructions and forms for clarification of the data collected. More information regarding these changes is provided here.
The 2009 Hazardous Waste Report contains the following four forms: RCRA Subtitle C Site Identification (Site ID Form), Waste Generation and Management (GM Form), Waste Received From Off-site (WR Form), and Off-Site Identification (OI Form). More information about these forms is provided here.
As noted previously, the 2009 Hazardous Waste Report is due to your State or EPA Regional Office by Monday, March 1, 2010. Your State reporting requirements or forms may differ from the Federal requirements. Return your completed Hazardous Waste Report to the address listed for your State or Regional contact: http://www.epa.gov/osw/inforesources/data/form8700/contact.pdf.
Be sure to make a photocopy of your completed Hazardous Waste Report and keep a copy for at least three years from the due date of the report as required by 40 CFR 262.40(b).
If you have any questions about RCRA Biennial Hazardous Waste reporting requirements and whether your facility may be subject to these regulations, please contact Paul Tomiczek III, REM, P.E. at email@example.com or 800-365-2324. More information on RCRA Biennial Reporting obligations, and detailed instructions for completing the hazardous waste report are provided at http://www.epa.gov/waste/inforesources/data/br09/br2009rpt.pdf.
Over 650 stakeholders in Pennsylvania’s rapidly growing oil and gas industry gathered in State College, Pennsylvania on January 11th and 12th of 2010 to participate in the Pennsylvania Department of Environmental Protection’s (PADEP) Regulatory Training for the Oil and Gas Industry. The attendees included, among others, representatives from exploration and production groups, midstream operators, consulting engineering firms, and the PADEP. The purpose of the presentation was to provide industry training and updates on permitting, policy, and regulations in Pennsylvania pertaining to the oil and gas operations.
The 1½ day training session focused on PADEP’s oversight of the following aspects of the industry:
- Erosion and Sedimentation Control Permitting for Oil and Gas Construction Activities
- Impoundment Permitting for Marcellus Shale Gas Wells
- Waste Reporting and Disposal
- Stream and Wetland Protection and Permitting
- Spill Reporting Requirements
- Water Management Plans and Water Use Reporting Requirements
While the training session was intended for Pennsylvania’s oil and gas industry in general, the focus of the presentations and the reason for the overwhelming attendance was the development of the Marcellus Shale play. The Marcellus has presented unique challenges for both operators and regulators in that the process of developing and completing a typical Marcellus well involves many elements and development at a scale atypical of traditional oil and gas exploration in Pennsylvania. Increased well development and vastly increased quantities of gas are spurring the development of gathering lines, transmission lines, and gas treatment, fractionation, and compression facilities across the Commonwealth. Increased current and projected activity and the processes necessary for successful extraction of natural gas from the Marcellus shale have spurred additional regulation and prompted the PADEP to provide training and informational sessions such as the recent event in State College to communicate both new and existing regulatory requirements to stakeholders.
The PADEP has implemented new regulation or applied existing regulations to all aspects of the Marcellus development with the goal of protecting Pennsylvania’s natural resources. Earth disturbance associated with natural gas development projects on sites in excess of five acres is regulated under the ESCGP-1 general permit. The construction of impoundments to hold fresh water for use in the hydraulic fracturing process and to receive produced water from the wells is regulated under PADEP’s Chapter 105 Dam Safety and Waterway Management Program. The permitting of impacts to streams, wetlands and other water bodies is also regulated under the Chapter 105 program and by the US Army Corps of Engineers. Approvals for use of water in the drilling and hydraulic fracturing process must be obtained through the PADEP Bureau of Oil and Gas through the Water Management Plan process and the Susquehanna River Basin Commission or Delaware River Basin Commission, where applicable. Waste disposal and treatment is regulated through the PADEP Bureaus of Oil and Gas and Waste Management. Operators are required to keep records of their waste handling, sampling, transport, and disposal activities and provide annual reporting to PADEP.
Future postings will provide more detailed information on the various aspects of the development of Marcellus Shale gas resources in Pennsylvania and other states. Specific questions about the topics identified in this posting can be answered by directly contacting our experts, Dustin Kuhlman at 800-365-2324 or firstname.lastname@example.org, Paul Kanouff at 800-899-3610 or email@example.com.
Further information on the Marcellus Shale and the regulatory framework for managing the development of this resource is available at the following web sites:
- PADEP Bureau of Oil & Gas – Marcellus Shale Home Page: http://www.dep.state.pa.us/dep/deputate/minres/oilgas/new_forms/marcellus/marcellus.htm
- Marcellus Shale Coalition: http://www.pamarcellus.com/
- Independent Oil and Gas Association of Pennsylvania: http://iogapa.org/
- Pennsylvania Oil and Gas Association: http://www.pogam.org/
Navigating Muddy Waters – New Effluent Limitation Guidelines Will Impact 21,000 Construction Sites Annually
On November 23, 2009, EPA released the final Construction & Development Effluent Limit Guidelines (C&D ELG). The final C&D ELG will impact all construction sites disturbing more than one acre by imposing non-numeric effluent limitations. More importantly, the C&D ELG will impose numeric effluent limits for the first time on all construction disturbing more than 10 acres within approximately 4 years. Most construction sites will need to use Passive Treatment Systems (PTS) to achieve those limits rather than the typical erosion and sediment control measures currently in use. EPA estimates as many as 21,000 construction sites annually would need to meet those numeric limit standards.
In the past, sediment control practices have generally been designed based upon a rule of thumb. Many states rely on 1800 ft3/acre of drainage (or disturbed acre), which doesn’t take into consideration the discharge quality. In fact, a sediment control measure can have an 80% settling efficiency and still produce a turbid (muddy) discharge. With this in mind, EPA has been struggling since early 2000 to establish a C&D ELG, with prodding from environmental groups.
In November 2008, EPA published a draft C&D ELG that set the ELG (turbidity) at 13 Nephelometric Turbidity Units (NTUs) for sites that disturbed 30 acres or more, were located in areas of the country with high rainfall intensity, and located on soils that had at least 10% clay. That incredibly low turbidity limit (13 NTUs) severely limited the stormwater treatment options to Active Treatment Systems (ATS) that, simply put, look and function like small waste water treatment plants. EPA requested public comment on the draft rule and requested additional data on the cost benefit analysis, treatment feasibility, and other components. Concerns mounted as those affected began questioning the draft rule, particularly the feasibility of achieving the 13 NTU discharge standard.
EPA published the final C&D ELG in November 2009 with major revisions based on the comments received. EPA chose to greatly simplify the rule and increase the numeric standard. Below is a summary of the final rule:
- All construction projects must install best practicable control technologies.
- Sediment basins and other impoundments must be dewatered from the surface.
- The ELG has been set at 280 NTUs. This limit is a daily maximum average, based upon sampling for storms up to the 2 yr, 24 hr storm. Discharges from storm events greater than the 2 yr, 24 hr are not required to meet the ELG.
- Discharges from construction sites must meet an effluent limitation guideline as follows:
- Within 18 months of the effective date of the rule (August 2011), sites disturbing 20 acres or more must meet the ELG.
- Within 4 years of the effective date of the rule, sites disturbing 10 acres or more must meet the ELG.
- For both scenarios above, the size limitations apply to “larger common plans of development” like subdivisions with multiple small lots.
Each state will need to marry the final C&D ELG with their existing monitoring plans, which will be a huge task. Additionally, EPA has noted that as each state’s construction stormwater permit comes up for renewal, these requirements must be inserted. EPA is the permitting authority in four states. Their general permit is due to expire in June 2011 and will be reissued with the ELG requirements in it at that time. Interestingly, North Carolina’s permit was in the midst of renewal when the ELG rule was finalized, and EPA only allowed their permit to be renewed for 18 months (through August 2011). After that date, the reissued permit must include the ELG requirements.
As indicated earlier in this blog, PTS will generally be required to meet the numeric standard of 280 NTUs. A PTS incorporates a flocculant with a standard construction site practice. An example of a PTS is a jute-lined ditch that has been impregnated with polyacrylamide (PAM). Design components that must be considered include mixing zones and settling zones. At this point, we don’t have design tools that dictate the amount flocculant to be used on a site. Flocculants and soils must be matched (not every flocculant works on every soil), and the applications tweaked in the field for peak performance. Then the flocculant must be reapplied after rain events.
You can expect to have the ELG requirements inserted into the permit language if your state’s permit expires before August 2011. If, however, your permit was reissued before the rule was finalized and without the ELG language in it, EPA could administratively open the permit to have the language inserted into it. I suspect that between June 2011 (when EPA’s Construction General Stormwater permit expires) and August 2011 (the deadline to begin implementing the ELG) some permits may be administratively opened. That option is certainly possible.
If you have any questions about the C&D ELG, how it may impact an upcoming project, and how you can meet the numeric standard, contact CEC’s Nashville office at (800) 763-2326.